This invention relates to improved methods and apparatus, for investigating the characteristics of subsurface earth formations traversed by a borehole, and more particularly relates to methods and apparatus for digitizing and processing an acoustic signature to determine selected formation characteristics.
It is well known that oil and gas are found in subsurface earth formations, and that wells are drilled into these formations to recover such substances. What is not generally known is that, for various reasons, the contents, if any, of most such formations do not automatically discharge into the well bore upon being penetrated. However, it is usually necessary to survey or "log" the entire length of the borehole to locate those formations of interest, before the well can be completed to produce the oil or gas.
There is no single well logging technique or device which can provide a direct indication of oil or gas in a particular formation of interest. Instead, the logging techniques which are most commonly used are those which measure various physical parameters of the earth substances adjacent the borehole, whereby such information can then be used according to selected functional relationships to determine which of those formations are of probable or possible value.
For example, it will be readily apparent that if the oil and gas are diffused or dispersed in the cavities or the pore spaces within a formation, then a formation of greater porosity will more likely contain producable amounts of oil or gas than will a formation of lesser porosity. Accordingly, an indication of the relative porosity of the earth materials along the borehole will obviously be of value in determining the depths at which oil and gas in suitable quantities for production will most likely be found.
Originally, well logging was performed by a sonde or logging "tool," which was merely suspended on the end of a logging cable, at the bottom of the borehole, and then was raised progressively through the borehole as it generated measurements of one or more earth parameters. Circuitry was usually provided in the sonde for converting such measurements into appropriate electrical signals which, in turn, were transmitted to the surface by one or more electrical conductors within the logging cable. Recording apparatus at the surface was provided to receive and record such signals in correlation with a suitable indication of the borehole depth at which the signals were derived.
As hereinbefore stated, various different logging techniques and apparatus have been devised and used in such manner, some being more suitable than others depending upon the different conditions existing in the borehole. For example, devices and techniques have long been used to measure the travel time or velocity of an acoustic pulse moving through such formations. In such cases, the measurements are usually transformed into electrical energy that is representative of the magnitude of this earth parameter being measured.
The earliest acoustic logging device, as shown in U.S. Pat. No. 2,651,027 issued Sept. 1, 1953 to C. B. Vogel, included a single acoustic transmitter and one acoustic receiver. The instrument provided an indication of the seismic wave velocity over a relatively large formation interval, such as five feet. A demand for increased accuracy in measurements and more detailed formation characteristics resulted in the development of the dual receiver acoustic logging tool.
The dual receiver acoustic logging tool consists of a single acoustic energy transmitter and two acoustic receivers spaced apart by some short distance, as for example one foot. This system measures the time required for acoustic energy to travel the distance equal to the separation of the pair of acoustic receivers. The acoustic transmitter is caused to emit energy which travels by way of the adjacent formations to the nearest receiver location. The time required for the acoustic energy to travel, by way of the adjacent formations, the distance between the near receiver and the far receiver location is measured, thus providing an indication of acoustic velocity for the area of the borehole formations located between the receiver stations. While an improvement, the dual receiver acoustic logging system proved less than desirable in that the information received was effected by the positioning of the instrument within the borehole. When the acoustic tool was in a tilted position in the borehole, unreliable velocity measurements resulted.
To provide a more accurate measurement of the acoustic characteristic of subsurface formations a dual transmitter--dual receiver acoustic instrument was introduced. This acoustic logging tool is equipped with an upper transmitter, an upper receiver, a lower receiver and a lower transmitter which are operated to obtain independent measurements representing acoustic energy traversing the formations from above and below the receivers and providing at least two time measurements which are averaged, yielding an average travel time. By this method the instrument compensates for such factors as tool position within the borehole.
The activation or "firing" of an acoustic transmitter of the well logging tool will cause a burst of acoustic energy to be radiated outwardly into the borehole and surrounding formations. The acoustic energy travels toward the receivers through the well fluid and the surrounding formations. Upon arriving at a receiver, the acoustic energy is converted by the receiver into an electrical signal, oscillatory in character, commonly referred to as an acoustic signature. The signature can be either processed within the instrument or telemetered to a surface location for processing to derive selected formation characteristics.
The processing of an acoustic signature has concentrated on several waveform characteristics to yield selected formation information. The amplitude of one or more oscillations of the acoustic signature waveform can be measured to provide an indication of formation fracturing or the quality of bonding of cement to a casing along a length of the cased borehole. Additionally, travel time of the acoustic wave through a formation interval can be calculated making a time based measurement over a selected portion of the acoustic signature. One method for measuring and calculating velocity, or the inverse travel time, can be found by reference to U.S. Pat. No. 3,257,639, issued June 21, 1966 to F. P. Kobesh.
In the prior art, velocity or travel time measuring has proved to be the most critical and most difficult measurement to make on an accurate and reliable basis. As hereinbefore mentioned, the acoustic signature is represented by an oscillating, or ringing electrical signal. The object is to measure a time from some fixed point on the signature, such as the instant of transmitter firing to a second point on the signature represented by the detection of acoustic energy generated by such transmitter firing arriving at a receiver location. The difficult measure point on the acoustic signature to reliably and consistantly determine is the arrival of the acoustic energy at the receiver location.
That portion of the acoustic signature representing the arrival of the transmitted acoustic energy at a receiver location is continually changing in character due to formation effects, noise generated due to the tool traversing the borehole and distortion caused by the transmission of the signature to a surface location through an electrical conductor within the logging cable. Changes in formation characteristics results in a continuously varying amplitude of the received electrical signal and a varying frequency of the oscillations generated in the detection of the transmitted energy. Early efforts made at detecting the second measuring point, on the representative received signal, were directed at detecting the point at which the first positive half-cycle of the received waveform crossed from a positive voltage level to a negative voltage level, or stated another way, crossed the zero voltage reference level. The measuring point was unsatisfactory due to distortion in the first half-cycle of received waveform. The distortion can be due to one or more of the factors hereinbefore described, and results in an inaccurate velocity and travel time calculation.
An alternative second measure point, was the first point of coincidence of the first half-cycle of received acoustic energy and a zero voltage reference level. This point was turned the "zero crossing point." Several factors in processing the analog acoustic signature, to determine the zero crossing point, resulted in a less than desirable measurement. At times the amplitude of the received signal varies enough that instead of detecting the first zero crossing point, the detection circuitry would jump or skip out in time along the acoustic signature to the second zero crossing point resulting in "cycle skippings" and an inaccurate measurement.
Additionally, the logging tool being dragged up the borehole on the end of a cable generated noise which could appear on the acoustic signature prior to the received signal. In such instance the point of detection would jump or move to detect the noise signal producing a velocity measurement more rapid than that of the formation encountered. Typically, these two instances of measurement point detection error were controlled by the operator visually monitoring the acoustic signature on an oscilloscope and manually adjust the system gain to obtain the proper detection point. In most instances the operator was unsuccessful in his attempts to make the required adjustments to obtain the degree of accuracy and reliability of the measurements desired.
To make the measurement more accurate a small threshold voltage circuit was added making the detection point not the first point of coincidence between the signature and a zero voltage reference level, but rather some small voltage level above the zero voltage level. This voltage level was selected to be above the level of most noise generated due to instrument movement. While the threshold detection point has proven to be more satisfactory than the prior detection points, it still fails to provide the most accurate detection point possible for calculating velocity and travel time. The slope of the first half-cycle of the received signal is not a constant. This slope can change due to the aforementioned distortion resulting from the transmission of the signature to the surface by way of a conductor within the logging cable or can change as a result of formation effect upon the acoustic energy. By having a coincidence detection point above the zero voltage reference level changes in waveform slope are reflected as inaccuracies in velocity and travel time computations due a changing point of coincidence between the reference level and the acoustic waveform.
These and other disadvantages are overcome with the present invention by providing method and apparatus for converting an acoustic signature into a digital format and performing accurate and reliable determination of selected acoustic signature parameters.